This invention relates to turbine meters of the type used to measure the flow of gas by converting kinetic energy of the flowing gas to rotation of a turbine which has its axis parallel to the path of gas flow.
Turbine meters are used to measure both the flow of liquids and the flow of gases. However, the theory of operation of gas turbine meters differs somewhat from that of liquid driven meters due to the differences in the density and kinematic viscosity of the two fluids. Since liquids are essentially incompressible, the density of liquids does not vary significantly with pressure or temperature. Also, the density of liquids is relatively high so there is ample driving torque from liquid flow to overcome mechanical friction in the meter. Thus, small changes in retarding torques, for example due to increases in friction between moving parts, do not affect the performance of liquid turbine meters. Conversely, the density of gas is relatively low so that gas turbine meters are highly sensitive to changes in retarding torques within the meters, especially at low pressure and low flowrates. Changes in kinematic viscosity do affect the performance of both gas turbine meters and liquid turbine meters.
The total volume of gas passing through the meter is determined by counting the number of revolutions of a measuring rotor mounted within the meter. Gas turbine meters are known as inferential meters because they infer how much gas has passed through by observing something else. A gas turbine meter is a gas velocity measuring device. The actual flowrate can be inferred from the velocity of the gas because the cross-sectional area of the annular passage preceding the rotor is a known.
The driving energy to turn the rotor is the kinetic energy, or energy of motion, of the gas being measured. The gas impinges on rotor blades mounted on the measuring rotor and overcomes retarding forces that inhibit the rotor from turning. Because the density of gas is low, it is necessary to reduce the cross-sectional area of the gas pipeline in which a gas turbine meter is mounted to accelerate the flow of the gas to a higher kinetic energy which allows the gas to be measured by the gas turbine meter. An inlet flow guide, or flow straightener, serves to reduce the area through which the gas flows to approximately one-half the area of the pipe in which the turbine meter is installed. Reducing the cross-sectional area of the flow path of the gas increases the velocity of the gas proportionately when the gas flowrate remains constant. Due to the higher density of liquids, liquid turbine meters do not have to accelerate liquids to measure their flow.
Gas turbine meters are commonly installed in pipe lines used in the natural gas industry for the measurement of the flow of large volumes of gas. The volumes are often so large that small errors in measurement can result in large losses of revenue to gas transmission companies and local distribution companies. An example of the magnitude of losses which can occur was presented in a 1992 technical publication of the Netherlands Measurement Institute. Consider a 12-inch turbine meter operating at a pressure of 580 psig and having a gas volume which is 59% of maximum capacity. Assuming the cost of natural gas is $0.0037 per cubic foot, an error of only 0.2% results in a loss of revenue of $160,000 per year. Clearly it is vital to maintain the accuracy of gas turbine meters.
Each gas turbine meter must be separately calibrated to determine its accuracy after it is manufactured. Calibration is necessary because normal, minor variations in meter components cause each gas turbine meter to register a slightly different volumetric flow for a given volume of gas. By way of example, from meter-to-meter blades on turbine measuring rotors vary slightly in shape due to minor manufacturing inconsistencies. As a result, each turbine measuring rotor rotates at a slightly different speed for gas flowing at the same velocity. Similarly, separate sets of measuring rotor bearings of the same make and model can impose slightly different frictional forces on the rotors of separate meters on which they are mounted. Additionally, a gas turbine meter normally has a mechanical register, sometimes called an index, which gives a reading of gas flow volume on a set of dials. A register is typically connected to a turbine measuring rotor through a coupling which includes gears, magnetic couplings and other components which load the turbine rotors of different gas turbine meter to a somewhat different extent. As a result, each gas turbine meter will register its own unique flow level for a given volume of gas.
At the time of manufacture of a gas turbine meter, the accuracy of a meter is proved by testing the meter against a known standard such as a master meter or a bell prover or a sonic nozzle. At a given temperature, a given gas line pressure and a given gas flowrate, the volume of gas registered by the meter is compared to the actual volume of gas which flowed through the meter as determined by the standard. This ratio of the volume of gas measured by a meter's mechanical register to the actual volume of gas flowing through the meter is called the accuracy of the meter. The calibration factor of a meter, referred to by the letter "K," expressed in terms of pulses per unit of volume flowing through a meter, is the amount by which the registered reading of the meter is divided to get a 100% accurate reading. For each of a given series of line pressures at which a gas turbine meter may operate, the K factors are determined for a range of flowrates expected for the meter and a table of these K factors is provided with each meter.
After a gas turbine meter has been installed and is operating, the accuracy of the meter can change over time as a result of factors such as damaged components, increased friction between components due to wear or due to contamination carried by gas flowing through the meter. Thus, there is a need to periodically prove gas turbine meters in the field.
There are currently several methods of proving gas turbine meters while these meters are installed in gas pipelines. These methods include using critical flow provers, sonic nozzle provers and in-line orifice meters. However, the most widely used method of proving meters in the field is by transfer proving. That is, by removing the meter or at least the meter's measuring cartridge from the pipeline, calibrating it with air at atmospheric pressure and then taking into account any changes in accuracy due to factors such as pipeline pressure, gas composition and the possible effects of flow disturbances. However, each of these methods of proving meters in the field is time consuming, interrupts the normal operation of the gas turbine meter and results in undesirable expenses.
By way of explanation, critical flow orifice provers and sonic nozzle provers are devices that operate with a pressure drop across their inlet ports and outlet ports which is above a critical pressure ratio for each such device. The ratio of outlet to inlet pressure required for the operation of the critical flow orifice prover is less than 53% and for the sonic nozzle prover is less than 81%. These provers, which are installed in a pipeline in-line with a gas turbine meter to be proved, are fixed flow devices, meaning that an orifice or nozzle with a given throat diameter will prove only one volumetric flowrate. As a result, different sized orifices or nozzles must be used to generate an accuracy curve over the operating flow range of the gas turbine meter being proved. Changing orifices or nozzles requires that gas be made to bypass this device and that the orifice or nozzle be depressurized. This procedure is time consuming and interrupts the service of the meter. Additionally, optimum accuracy of a critical flow orifice prover or a sonic nozzle prover requires a determination of gas composition, involving sampling of gas for lab analysis or transporting a portable gas chromatograph to the site for gas analysis.
In-line orifice meters present some of the same difficulties faced with critical flow orifice provers and sonic nozzle provers. In-line orifice meters are placed in a pipeline in line with a meter to be proved and operate by measuring the differential pressure across an orifice plate in the flow stream of the gas being measured. Multiple orifice plates may be required to obtain an accuracy curve over the flow range of the gas turbine meter, requiring that the flow of gas bypass the orifice meter and the orifice meter be depressurized for the change of plates. Additionally, this type of meter also requires a knowledge of the specific gravity of the gas being measured, that is the composition of the gas, again requiring lab analysis of the gas or the use of a portable gas chromatograph on site.
Transfer proving consists of testing a meter against a reference meter of known accuracy. The meter being tested is removed from the pipeline from which it is installed and then installed in series with a reference meter. Air is passed through both meters and volume readings are compared to evaluate the accuracy of the gas turbine meter being tested. The removal of the gas turbine meter being tested from the pipeline interrupts the normal service of the meter. Additionally, the accuracy evaluation cannot account for the possible effects of flow disturbances within the pipeline on the accuracy of the meter. Most transfer provers calibrate meters at atmospheric pressure since elevated pressure transfer provers are very costly to own or lease. Additionally, air is the test fluid. Thus, changes in accuracy resulting from pipeline pressure or gas composition are not accounted for when using a transfer prover at atmospheric pressure. Furthermore, the capacity of most transfer provers is inadequate for testing larger turbine meters.
A more recent development has sought to minimize or avoid a need for proving gas turbine meters by compensating for inaccuracies which occur in their operation. This development consists of a gas turbine meter which uses two rotors mounted in close proximity to each other so that they interact fluid dynamically. The basic principle of operation is that meter accuracy and changes in meter accuracy are proportional to the deflected angle of fluid exiting a measuring rotor.
A downstream sensing rotor senses and responds to changes in the exit angle of fluid from turbine blades of the measuring rotor so that the difference in rotor speeds remains constant. The sensing rotor and the associated electronic circuitry are not designed to measure accuracy of the meter, but to automatically adjust the electronic output so that the output of the meter is theoretically 100% accurate. The amount of adjustment required to maintain 100% accuracy is provided for determining the relative change in condition of the meter from its initial calibration. Meters of this type are described in U.S. Pat. No. 4,286,471 Lee, et al. and U.S. Pat. No. 4,305,281 Lee, et al.
However, the design of this type of turbine meter assumes that the system is functioning correctly. If a malfunction exists that results in incorrect flowrates, a customer would not be aware of the problem. Additionally, because the rotors are fluid dynamically coupled, a complete failure of one rotor due to friction or clogging will render the meter inoperative. Furthermore, the rangeability of this gas turbine meter, that is the ratio of maximum to minimum capacity, is reduced approximately 33% from a conventional turbine meter due to the small sensing rotor blade angle and a necessity for fluid dynamic interaction between the two rotors.
Thus, there still remains a need in the natural gas industry for some means or method of rapidly and accurately proving gas turbine meters in gas pipelines under actual operating pressures and temperatures without removing the meters form the pipelines and without interrupting normal service of the meter.